The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
In the art of recovering hydrocarbon values from subterranean formations, it is common, particularly in formations of low permeability, to hydraulically fracture the hydrocarbon-bearing formation to provide flow channels to facilitate production of the hydrocarbons to the wellbore. Fracturing fluids typically comprise a water or oil base fluid incorporating a polymeric thickening agent. The polymeric thickening agent helps to control leak-off of the fracturing fluid into the formation, aids in the transfer of hydraulic fracturing pressure to the rock surfaces and, primarily, permits the suspension of particulate proppant materials which remain in place within the fracture when fracturing pressure is released.
Typical polymeric thickening agents for use in fracturing fluids are polysaccharides polymers. For example, fracturing fluids comprise galactomannan gums such as guar and substituted guars such as hydroxypropyl guar or carboxymethylhydroxypropyl guar. Cellulosic polymers such as hydroxyethyl cellulose may also be used as well as synthetic polymers such as polyacrylamide. To increase the viscosity and, thus, the proppant carrying capacity as well as to increase the high temperature stability of the fracturing fluid, crosslinking of the polymers is also commonly practiced. Typical crosslinking agents comprise soluble boron, zirconium or titanium compounds. These metal ions provide for crosslinking or tying together of the polymer chains to increase the viscosity and improve the rheology of the fracturing fluid.
Of necessity, fracturing fluids are prepared on the surface and then pumped through tubing in the wellbore to the hydrocarbon-bearing subterranean formation. While high viscosity is a desirable characteristic of a fluid within the formation in order to efficiently transfer fracturing pressures to the rock as well as to reduce fluid leak-off, large amounts of hydraulic horsepower are required to pump such high viscosity fluids through the well tubing to the formation. In order to reduce the friction pressure, various methods of delaying the crosslinking of the polymers in a fracturing fluid have been developed. This allows the pumping of a relatively less viscous fracturing fluid having relatively low friction pressures within the well tubing with crosslinking being effected at or near the subterranean formation so that the advantageous properties of the thickened crosslinked fluid are available at the rock face.
One of the challenges in fracturing deep wells is reducing surface treating pressure. Deeper reservoirs usually have higher bottomhole pressures and deeper wells give rise to higher friction pressure. These factors lead to increase in treating pressure when stimulating these wells, sometimes in excess of 15,000 psi, which is the current limit of the completion tubular and pumping equipment. One way to reduce surface treating pressure is to increase fluid density, and take advantage of the hydrostatic head (Phydrostatic) provided by heavy brines (composed of water and a large amount of salts) to formulate the fluid (equation 1); here, PBHP refers to the treating pressure at the point where the fracture is being created, and Pfriction refers to the friction pressure.Psurface=PBHP+Pfriction−Phydrostatic  (1)
Fluids containing polymers crosslinked by metal ions display high viscosities at temperature in excess of 150° C., making them suitable for fracturing deep, high temperature wells. However, these metal-crosslinked fluids are typically shear-sensitive, i.e. they irreversibly lose viscosity if sheared at high rates that are commonly encountered in the tubulars.